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Last Updated: June 13, 2018
Business Trends

Market Watch

Headline crude prices for the week beginning 11 June 2018 – Brent: US$74/b; WTI: US$66/b

  • Oil prices held their ground, as dissenting voices within OPEC point to the difficulty of agreeing on an output boost at the upcoming meeting in Vienna.
  • Unofficial requests from the US to key OPEC members to hike output raised eyebrows last week, with Saudi Arabia, Kuwait, the UAE and Algeria looking likely to band together with Russia to push for a supply increase.
  • With Saudi Arabia boosting its daily oil output in May by 162,000 b/d to 10.03 mmb/d – the highest level since October 2017 – individual output rises already look like they are beginning.
  • However, Iraq’s oil minister said that OPEC should not be influenced by pressure to pump more oil, warning that unilateral decisions could lead to the collapse of the fragile alliance within the OPEC group.
  • This complicates matters ahead of the bi-annual meeting in Vienna, with Iraq likely to side with Iran and Venezuela on not raising output, as well as OPEC’s reported refusal to discuss US sanctions on Iran at the meeting.
  • Meanwhile, Venezuela is struggling with a huge crude export backlog, reportedly almost a month behind delivering crude to its customers, putting PDVSA in danger of declaring force majeure on shipments.
  • In the US, growing output in the Permian is causing another bottleneck – labour shortages, with some firms reportedly doubling pay to attract workers.
  • The US active rig count continues to grow, though the rise has been stemmed by the recent fall in crude prices. One new oil and one new gas rig entered service last week, bringing the total number to 1,062.
  • Crude price outlook: A successful initial meeting between North Korea and the US in Singapore should see some political risk abate, but the direction of prices is dependent on whether or not OPEC can come to an agreement. We expect prices to remain steady at US$74-75/b for Brent, and US$64-65/b for WTI.

Headlines of the week


  • Iran and Iraq have begun oil swaps using Kirkuk crude – to be refined in Iran’s Kermanshah and shipped in equal amounts back to Iraq’s southern ports – as Tehran looks for way to circumvent US sanctions with its Arab ally.
  • Qatar Petroleum has bought a 30% in two ExxonMobil subsidiaries in Argentina, gaining access to seven blocks in the promising Vaca Muerta play.
  • ExxonMobil has completed its purchase of half of Equinor’s interest in the BM-S-8 offshore block in Brazil, part of the pre-salt Carcara oil field.
  • Saudi Aramco has raised pricing on key crude grades for Asia to their highest levels since 2014, facing less competition for market share from Iran and Venezuela as well as healthy demand across key markets.
  • Argentina looks set to offer 48 blocks in its first ever upstream licensing round in November, attracting attention from Anadarko, CNOOC and Petronas.
  • Production at the giant Kashagan offshore field in Kazakhstan should hit its target of 370,000 b/d by the end of the year, and could naturally hit as much as 500,000 b/d as partners on the project mull a second development phase.


  • China’s crude oil imports in May eased slightly to 9.2 mmb/d after hitting a record 9.7 mmb/d in April, as key refineries entered maintenance and plants in Shandong were ordered to scale back to ensure blue skies in Qingdao.
  • The new Total-Borealis-NOVA joint venture, Bayport Polymers, has broken ground on its new US$1.7 billion ethane cracker in Port Arthur, Texas. 
  • Vietnam’s second refinery Nghi Son expects to export its first petrochemical shipment this month, entering full operations by August 2018.
  • Kazakhstan is aiming to rival Russia in supplying fuel products to Central Asia following the planned upgrade of its refineries, with the government considering lifting a statewide ban on light oil product exports.

Natural Gas/LNG

  • ExxonMobil and Rosneft have agreed to a capacity of at least 6.2 mtpa for their joint venture US$15 billion Far East LNG project in Sakhalin.
  • The Philippines’ Phoenix Petroleum has agreed to partner with CNOOC to build an LNG import terminal in the country, which is separate from the government’s efforts to establish infrastructure to replace Malampaya gas.
  • Australia’s AIE, together with Japan’s JERA and Marubeni, have proposed building an LNG import terminal at Port Kembla near Sydney to ease the ongoing natural gas supply crunch along Australia’s east coast.
  • Commercial operations at the Golar LNG FLNG project in Cameroon have begun, using an oil tanker reconverted in the Hilli Episeyo FLNG vessel.
  • Poland is aiming to complete the new Baltic Pipe gas pipeline to Norway via Denmark by 2022, as it aims to reduce reliance on Russian gas.
  • Eni is on track to deliver first gas from its operations in Ghana this month, which should be enough to double the country’s national output by year-end.
  • Oil Search has reportedly hit gas at the Kimu 2 wells in the interior of Papua New Guinea, within the target Alene reservoir.


  • India’s private oil retailer Essar Oil has been rebranded as Nayara Energy at a recent meeting of shareholders, as part of a corporate repositioning.

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U.S. refineries running at near-record highs

U.S. gross refinery inputs

Source: U.S. Energy Information Administration, Weekly Petroleum Status Report

For the week ending July 6, 2018, the four-week average of U.S. gross refinery inputs surpassed 18 million barrels per day (b/d) for the first time on record. U.S. refineries are running at record levels in response to robust domestic and international demand for motor gasoline and distillate fuel oil.

Before the most recent increases in refinery runs, the last time the four-week average of U.S. gross refinery inputs approached 18 million b/d was the week of August 25, 2017. Hurricane Harvey made landfall the following week, resulting in widespread refinery closures and shutdowns along the U.S. Gulf Coast.

Despite record-high inputs, refinery utilization as a percentage of capacity has not surpassed the record set in 1998. Rather than higher utilization, refinery runs have increased with increased refinery capacity. U.S. refinery capacity increased by 862,000 barrels per calendar day (b/cd) between January 1, 2011, and January 1, 2018.

The record-high U.S. input levels are driven in large part by refinery operations in the Gulf Coast and Midwest regions, the Petroleum Administration for Defense Districts (PADDs) with the most refinery capacity in the country. The Gulf Coast (PADD 3) has more than half of all U.S. refinery capacity and reached a new record input level the same week as the record-high overall U.S. capacity, with four-week average gross refinery inputs of 9.5 million b/d for the week ending July 6. The Midwest (PADD 2) has the second-highest refinery capacity, and the four-week average gross refinery inputs reached a record-high 4.1 million b/d for the week ending June 1.

Gulf Coast and Midwest gross refinery inputs

U.S. refineries are responding currently to high demand for petroleum products, specifically motor gasoline and distillate. The four-week average of finished motor gasoline product supplied—EIA’s proxy measure of U.S. consumption—typically hits the highest level of the year in August. Weekly data for this summer to date suggest that this year’s peak in finished motor gasoline product supplied is likely to match that of 2016 and 2017, the two highest years on record, at 9.8 million b/d. The four-week average of finished motor gasoline product supplied for the week ending August 3, 2018, was at 9.7 million b/d.

U.S. distillate consumption, again measured as product supplied, is also relatively high, averaging 4.0 million b/d for the past four weeks, 64,000 b/d lower than the five-year average level for this time of year. In addition to relatively strong domestic distillate consumption, U.S. exports of distillate have continued to increase, reaching a four-week average of 1.2 million b/d as of August 3, 2018. For the week ending August 3, 2018, the four-week average of U.S. distillate product supplied plus exports reached 5.2 million b/d.

In its August Short-Term Energy Outlook (STEO), EIA forecasts that U.S. refinery runs will average 16.9 million b/d and 17.0 million b/d in 2018 and 2019, respectively. If achieved, both would be new record highs, surpassing the 2017 annual average of 16.6 million b/d.

August, 14 2018
Offshore discoveries in the Mediterranean could increase Egypt’s natural gas production

Egypt natural gas fields and select infrastructure

Natural gas production in Egypt has been in decline, falling from a 2009 peak of 5.8 billion cubic feet per day (Bcf/d) to 3.9 Bcf/d in 2016, based on estimates in BP’s Statistical Review of World Energy. The startup of a number of natural gas development projects located offshore in the eastern Mediterranean Sea near Egypt’s northern coast has significantly altered the outlook for the region’s natural gas markets. Production from these projects could offset the growing need for natural gas imports to meet domestic demand, according to the Egyptian government.

The West Nile Delta, Nooros, Atoll, and Zohr fields were fast-tracked for development by the Egyptian government and have begun production, providing a substantial increase to Egypt’s natural gas supply. The Zohr field’s estimated recoverable natural gas reserves of up to 22 trillion cubic feet (Tcf) would make it the largest natural gas field in the Mediterranean, based on company reports gathered by IHS Markit. The Zohr field is currently producing 1.1 billion cubic feet (Bcf) per day and is expected to increase to 2.7 Bcf per day by the end of 2019.

Natural gas production in Egypt has declined largely as a result of relatively low investment, according to Business Monitor International research. Meanwhile, domestic demand for energy has grown, driven by economic growth, increased natural gas use for power generation, and energy subsidies. With the exception of small declines in 2013 and 2014, natural gas consumption has increased every year since at least 1990, and it is up 19% from 2009, when domestic production peaked.

Faced with growing demand and declining supply, Egypt had to close its liquefied natural gas (LNG) export terminals to divert supply to domestic consumption. Egypt became a net natural gas importer in 2015, and although LNG exports resumed in 2016, Egypt’s net imports of natural gas continued to increase.

Egypt dry natural gas production, consumption, and trade

Source: U.S. Energy Information Administration, based on 2017 BP Statistical Review of World Energy

The Middle East Economic Survey (MEES) indicated that Egypt will still need to import small volumes of natural gas in the coming years, particularly for the power sector. MEES reported that the state-owned Egyptian Electricity Holding Company (EEHC) awarded contracts that would add 25 gigawatts (GW) to total generation capacity, 70% of which would come from natural gas-fired projects. Three combined-cycle natural gas turbine power plants with a total capacity of 14.4 GW will collectively require as much as 2.0 Bcf/d of natural gas when they become fully operational in 2020.

August, 15 2018
US Energy Exports Spared the Wrath of the Middle Kingdom

A threat. And then a backing off. As the trade war between the US and China escalates, both countries are moving into politically sensitive areas as they ratchet up the scale of the standoff. When the US first introduced tariffs earlier this year, they were limited to washing machines and solar panels. Then as President Trump moved into a broader range of goods, China responded with tariffs that were designed to maximise impact on Trump’s voter base. That meant the agriculture heartlands of the US in the Midwest where soybeans are grown and shipped in record numbers to China last year to feed its massive demand for animal feed and edible oils. Last week, the US imposed tariffs on an additional US$16 billion worth of Chinese imports, targeting technological sectors, and of course, China replied. The list included for the first time US crude exports, demonstrating China’s willingness to hit one of America’s most vibrant industries. And then, a few days later, it backed down, removing crude oil from the list. 

What happened?

Chatter among the industry suggests that Sinopec had lobbied for the removal. Even though growth has slowed down nominally, China’s fuel demand is still growing massively on an absolute level. In a year where Iranian crude exports are being squeezed by new American sanctions, China needs oil. It may have defied a request by the US to completely halt Iranian exports, but it has also promised not to ramp up orders as well. China imported some 650,000 b/d of crude from Iran last year. To replace even some of that will be challenging without tapping into growing American production, particularly since Sinopec and Petrochina are in a tiff with Saudi Aramco over prices, and the government wants to diversify its crude sources away from overreliance on Russia.

So crude was removed from the tariff list. Leaving only refined fuels and petrochemical feedstocks – tiny in demand except for propane, which has become a key feedstock for China’s petrochemicals producers through PDH plants. But since President Trump has mooted more tariffs, this time on US$200 billion worth of imports, China may have backpedalled for strategic reasons this time – Sinopec’s trading arm had suspended all US purchases until the ‘uncertainty passed’- but can still wield its potent weapon in the future. And not just on crude, but tariffs on LNG as well. The latter is more sensitive, given that many of the LNG projects springing up along the Gulf Coast are depending on projected Chinese demand. Cheniere just signed a 25-year LNG deal with CNPC and is hoping for more to come. That hope burns bright for now, but if the trade war continues escalating at its current pace, the forecast could get a lot cloudier. For now, US energy exports have been spared from the wrath of the Middle Kingdom. Enjoy it while it lasts.

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August, 14 2018